That led to rebuttals from green power backers, both from the business world and nonprofit world, arguing that wind and solar power output can be predicted and managed in ways that the state’s grid can handle -- if it’s planned for properly, and managed via the right technologies and proper regulatory and economic incentives.

In markets where wind and solar power are starting to approach a significant portion of total grid power -- such as Germany at the current juncture, and California in the coming years -- questions like these are starting to be asked with a lot more urgency. Good thing that we’ve got experts in the technical, regulatory and economic domains that pertain to this issue hard at work on figuring out some answers.

A number of those experts were on hand at last week’s 2013 ARPA-E Energy Innovation Summit in suburban Washington, D.C., where several panel discussions were dedicated to the subject of just how much distributed energy the grid can or can’t handle -- and what new technologies would be critical for integrating this new source of clean, yet unpredictable, energy.

The distributed, renewable grid is already upon us. Lauren Azar, a senior advisor to Energy Secretary Steven Chu, is charged with coordinating the Department’s overall efforts to strengthen and modernize the electricity grid. Speaking last Tuesday on a panel entitled “Breaking Through the 'Grid'-Lock ,” Azar told the audience that certain utilities -- such as California’s big three investor-owned utilities -- are already starting to face the challenge of significant penetration of distributed generation assets, mostly rooftop solar, on their existing operations.

In a Wednesday panel on distributed energy and intelligence, Geisha Williams, executive vice president of electric operations for solar-rich utility Pacific Gas & Electric, told me that increasing solar penetration causes several specific problems for PG&E. Those include handling the two-way power flows on distribution grids built to handle one-way power only, as well as the economic issues surrounding solar customers who are increasingly shifting from being purchasers of utility power to inhabiting a more nuanced, two-way economic relationship.

Clark Miller, associate director of Arizona State University’s Consortium for Science, Policy and Outcomes, said that these problems are exacerbated by the fact that utilities may know where all that distributed solar is, but don’t necessarily know how much power it’s generating at any given time. That creates a huge “shadow load” that utilities can’t see, but which can affect their operations, he said.

These pressures are going to quickly focus the attention of utilities and their financial backers on figuring out ways to manage these disruptions, Azar said. “As soon as utilities start to see a significant erosion of their revenues and the potential for stranded assets, that gets the business community involved -- that gets the financial community involved,” she said.

It’s hard to fairly spread the costs and benefits of the distributed green energy revolution. PG&E’s Williams told the audience at ARPA-E that solar-equipped utility customers present a particular challenge on the economic front. That’s because they can reduce or even eliminate their bills, while actually increasing the intensity of their use of the wires that connect their net-zero energy home to the grid, she said.

California’s big three utilities have been making their case to state regulators that these extra solar-related costs should be built into new rate structures that charge them for these network costs. But so far, the California Public Utilities Commission hasn’t been amenable to the concept, rejecting San Diego Gas & Electric’s network use charge rate case early last year.

But utilities are going to have to cover the costs of maintaining the grid in any case, Arizona State’s Miller said -- and without changes, that means that solar-equipped customers, who tend to be wealthier than not, may be pushing extra costs onto ratepayers that don’t have solar. Arizona state data shows that the wealthiest communities that have the most solar are getting the most benefit from incentives and reduced bills, he said, though programs like Arizona’s community solar initiative could help spread that out.

The definition of a “wires utility” is bound to change. Cheryl Roberto, a former commissioner with the Ohio Public Utilities Commission, said that one long-reaching effect of all this distributed energy is to change the definition of what a distribution utility does. In effect, self-generating customers “want to use our wires as batteries,” she said, relying on the utility not as the first choice for their energy needs, but as an energy source of last resort.

That can range from residential rooftop solar customers, who obviously need utility power at night, to more self-reliant customers like big commercial and industrial customers with combined heat and power (CHP) systems that allow them to run independently of the grid much of the time. “As regulators, we need to find out what the cost is to use these assets in new ways,” and create systems to manage them, she said.

Arshad Mansoor, senior vice president of research and development for the Electric Power Research Institute (EPRI), noted that utilities don’t just provide backup power to self-generating customers. They also provide the “start-up” power, in volumes or qualities needed to start up heavy loads like air conditioners or refrigerators in homes, or big industrial motors in industrial settings. “What’s the value of that?” he asked.

New models need to emerge to manage the distributed power. Audrey Zibelman, CEO of Viridity Energy, a startup focused on the intersection of smart customer power management and smart grid integration, said that the spread of distributed energy resources calls for new market mechanisms for managing them. As she put it, distribution utilities are going to have to start to do with their individual customers’ distributed resources what big regional grid operators like PJM, CAISO and ERCOT do for system-wide generation and demand management resources today.

That’s because “only the distribution utility can provide the level of visibility” into what’s going on on their distribution wires, she said -- it’s just too complex and small-scale a problem for the big grid operators to tackle. At the same time, it requires technology that’s much cheaper than the dedicated, high-speed IT and communications that link massive power plants and grid operations centers.

Jeffrey Taft, chief architect for Cisco’s smart grid business, told me during a Wednesday panel that this challenge calls for new distributed architectures to manage “transactive loads” between generation and demand resources at both macro and micro-grid scales. Of course, he added, it’s been difficult to properly balance the mix of economic imperatives and immutable laws of physics that are involved in balancing energy generation and consumption amidst a set of independent actors operating in a market for a product that’s delivered the instant it’s produced.

If the grid can’t be made flexible, new technologies won’t make it into the picture. Despite the complexity, it’s imperative that the industry come to common solutions for these problems -- because without them, utilities will be forced to hold off on the distributed energy revolution. That’s because all of these technological, regulatory and business-case solutions to the distributed energy challenge will have to abide by one golden rule: reliability. Keeping the lights on is a utility’s core responsibility, and any innovations that threaten that reliability metric simply won’t be allowed onto the grid, Azar said.

At the same time, utilities have to change their mindset on these challenges, said David Mohler, chief technology officer for giant U.S. utility Duke Energy. “We have to stop asking what could go wrong with this, and start asking what’s possible,” he said.